Imaging of microseismic events, particularly as a result of fracturing operations, is well known in the oil and gas industry. Conventional techniques used to image the placement of a fracture within a formation include, but are not limited to, the following: positioning sensors at surface in a surface array, such as in a Fracstar™ system as taught by MicroSeismic Inc., or as taught in U.S. Pat. No. 4,271,696 to Wood; burying sensors at surface in a buried array—such as in a Buried Array™ system as taught by MicroSeismic Inc.; and positioning sensors in remote wells such as taught by U.S. Pat. No. 6,935,424 to Halliburton and Pinnacle Technologies or as taught by U.S. Pat. No. 5,934,373 to Warpinski et al.
Prior art systems that utilize surface or near-surface arrays are located kilometers from the microseismic event locations and as such are limited to only observing larger magnitude events. Deployment and retrieval, if required, can be time consuming and expensive. Systems that are deployed in an adjacent vertical observation well are capable of detecting smaller magnitude events than surface systems, however require the existence of the adjacent well and are only optimally located, such as within several hundred meters, for a small number of frac ports. Systems that are deployed in an adjacent horizontal well, require the presence of the adjacent horizontal well and complicated equipment, such as a wireline tractor or pump assembly and a pump truck having fluid tanks at surface, or other means to deploy the sensor array into the horizontal portion of the wellbore.
The known prior art systems, having sensors which are not located within tools used for fracturing, operate independent of the fracturing operation and remote therefrom.
As taught in US Published patent application 2015-0075783-A1, a 371 application from PCT/CA2013/050329, and US Published patent application 2015-0135819, a 371 application from PCT/CA2013/050441, both to Kobold Services Inc. of Calgary, Alberta, Canada, each of which is incorporated herein by reference in its entirety, a Fracture Imaging Module “FIM” has been designed to attach to a distal end of a fracturing tool in a bottomhole assembly (BHA). The BHA is capable of a variety of types of fracturing operations including, but not limited to, annular fracturing, tubing fracturing, isolation fracturing or combinations thereof. Combining microseismic monitoring within the BHA reduces cost. Offset wellbores are not required and surface or subsurface arrays may not be required. Using embodiments of the BHA incorporating a FIM tool having at least two, and more particularly, three or more 3-component sensors, multi-stage fracturing with real-time microseismic monitoring can be performed within a single coiled tubing run as there is no need to trip the BHA out of the wellbore for each stage to permit separate apparatus, conventionally used to perform microseismic monitoring, to be run into the wellbore. Positioning of the FIM tool in the BHA improves the location of the microseismic sensors relative to the frac treatment area/stage to improve accuracy of monitoring microseismic events which are created by forcing the fracturing fluids into the formation under high pressure.
During the fracturing operations, the fracturing tool/BHA is exposed to vibration and movement when flowing fracturing fluid therethrough at fracturing pressures. The vibration and movement is transmitted to the FIM tool attached thereto which contributes to noise in the microseismic signals received therewith.
Noise, if an issue in the treatment wellbore, can be reduced so the microseismic signals can be detected and identified. US published application 2015-0135819 to Kobold Services Inc. describes one suitable means for removing noise from the microseismic signals using fiber optic cable as a noise detection and cancellation device. The fiber optic cable is run in coiled tubing used to deploy the BHA. The coiled tubing can be conventional coiled tubing or an electrically-enabled coiled tubing (CT), such as IntelliCOIL™, which is described and claimed in U.S. Pat. Nos. 8,567,657, 8,827,140 and 9,194,512, all to MTJ Consulting Services Inc. of Calgary, Alberta, Canada, each of which is incorporated herein by reference in its entirety.
Applicant is aware that others have deployed microseismic sensors in the treatment wellbore. Schlumberger deploys a series of horseshoe-shaped clamps to attach 3-component sensors to the casing. CT runs through the centre of the horseshoes clamps. The 3-component sensors are deployed uphole of the shallowest fracture port, typically in the vertical section of the wellbore and possibly through the build portion of the wellbore. However, the frac is pumped through the CT therefore, the 3-component sensors are not in contact with fluid flow. Such apparatus may be limited in observation distance to the frac ports nearest the heel of the wellbore.
Weatherford has a system which utilizes a wireline to position sensors above the frac zone. The noise of pumping the frac is significant and the results can be compromised.
Weatherford also has a process whereby a tool string comprising microseismic sensors is located downhole of the active frac port(s), the sensors being isolated via a retrievable bridge plug positioned between the frac ports and the sensors. The fracturing operation is suspended to deploy the array and the array must be retrieved after the frac is complete which adds two round trips to the operation at significant cost. The system is likely limited in observation distance to the uphole frac ports nearest the fixed array. Further, as the tool string needs to be retrieved from, and most likely deployed into, a live well, the system presents operational limitations and cost. Due to the limited length of a lubricator of a coil tubing rig for pressure deployment and retrieval, it may be difficult to achieve a significant array length.
Sensors deployed into a treatment wellbore are generally limited in length, in part by the length of the lubricator used to deploy the BHA. As a result of the limited length of the BHA and positioning of the sensors therein, the ability to optimally locate a microseismic event in 3D space, away from the wellbore, is exposed to errors. These errors may be significant.
BHA's are installed and removed from the live wellbore and can be pressure deployed. Using a known system, the BHA is installed in the live well, section by section, which is time consuming and introduces operational risks. Use of coiled tubing (CT) is well known in the oil and gas industry. Coiled tubing has many advantages, one of which is the ability to work in live, pressurized wells. CT is generally used to deploy various bottomhole assemblies (BHA) for a variety of live well applications. Coiled tubing mast rigs typically have a BHA lubricating capacity of about 12 to 15 m at a maximum. For this reason the lubricating length of the BHA at surface is generally restricted for live well applications. Conventional rigs with cranes may be used in combination with longer lubricators, such as from about 30 m to about 40 m, however this is very costly and not a common practice due to equipment availability and safety.
The industry is seeking cost effective, accurate fracture image placement information. To minimize cost of obtaining the fracture image data, there is great interest in accumulating microseismic data during an existing well intervention, such as by effectively and efficiently utilizing modules which can be added to a BHA that provides the conveyance at an acceptable cost.